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UBS Gas, Power & Coal Conference
Dallas, Texas March 3, 2011
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This presentation contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: the economic climate and growth in, or contraction within, our service territory and changes in market demand and demographic patterns, inflationary or deflationary interest rate trends, volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates, the availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material, electric load, customer growth and the impact of retail competition, weather conditions, including storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms, available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters, availability of necessary generating capacity and the performance of our generating plants, our ability to recover I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration costs through warranty, insurance and the regulatory process, our ability to recover regulatory assets and stranded costs in connection with deregulation, our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates, our ability to build or acquire generating capacity, including the Turk Plant, and transmission line facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates, new legislation, litigation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants, timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance), resolution of litigation (including the dispute with Bank of America), our ability to constrain operation and maintenance costs, our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities, changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market, actions of rating agencies, including changes in the ratings of debt, volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities, changes in utility regulation, including the implementation of ESPs and related regulation in Ohio and theallocation of costs within regional transmission organizations, including PJM and SPP, accounting pronouncements periodically issued by accounting standard-setting bodies, the impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans and nuclear decommissioning trust and the impact on future funding requirements, prices and demand for power that we generate and sell at wholesale, changes in technology, particularly with respect to new, developing or alternative sources of generation, other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events and our ability to recover through rates the remaining unrecovered investment, if any, in generating units that may be retired before the end of their previously projected useful lives.
Investor Relations Contacts
“Safe Harbor” Statement under the Private Securities Litigation Reform Act of 1995
Chuck ZebulaTreasurer
SVP Investor Relations614-716-2800
cezebula@aep.com
Bette Jo RozsaManaging DirectorInvestor Relations
614-716-2840bjrozsa@aep.com
Julie SherwoodDirector
Investor Relations614-716-2663
jasherwood@aep.com
Sara MaciochAnalyst
Investor Relations614-716-2835
semacioch@aep.com
3
Nick Akins - President
Rich Munczinski – SVP Regulatory Services
4
Table of Contents
Topic Page Company Overview/Strategy 5Regulatory 11Financial 13 Generation 20ESP Filing 23
5
American Electric Power
Serving electric customers in 11 states
AEP Fast Facts
5.3 million customers39 GW of generation capacity
39,000 miles of transmission lines
$17.7B Market CapitalizationBBB/Baa2/BBB credit rating
Regulated Electric Utility– Regulatory and economic diversity– Operating Company Model
Focus on Capital Allocation– Capital for Growth– Return of Capital to Shareholders– Pension Funding
Strong Balance Sheet– Stable credit ratings– Capital plan supported by cash flow– Strong liquidity position
Growth Opportunities– Capital for utility platform– Transmission projects
Dividend yield of 5%
6
Capital Allocation
Capital for Growth– Capital budget of $2.6B for 2011– Capital budget plan of $2.9B for 2012
Return of Capital to Shareholders– 12% increase in quarterly dividend in 2010 – Future dividend increases will grow with earnings
Capital to Reduce Risk– Voluntarily funded pension $500M in 2010– Allocating an additional $150M of funding for pension in 2011
In this economic recovery cycle, capital allocation requires balance for spending that considers the obligation to serve, the ability to obtain rate increases, a balance
sheet to support the plan, and the total return proposition to shareholders
7
Actions: Empower operating company employees to drive results
Efficiently allocate capital
Demonstrate O&M and capital expenditure discipline
Identify asset renewal strategy for investing in traditional distribution and transmission assets that enhance reliability and customer satisfaction
Enable long-term planning discussions with regulators and legislators
Managing Operations and Investment
Challenges:Required refinement of the operating company model and improved line-of-sight management due to decreased load growth, regulatory lag, reduced rate headroom, and environmental challenges
Expected Outcomes:Optimize spending for more efficient return on investment
Improve dialogue with customers and regulators Minimize lag in rate recovery
8
Highly Diversified Regulated Utility Platform
Residential30%
Commercial27%
Industrial33%
Wholesale * 10%
* Wholesale includes sales to municipal and cooperative power systems, other wholesale, and other retail sales
2010 Retail Load2010 On-Going Earnings Contribution
Region # of customers
Appalachian Power (incl. TN) 1,004,000Indiana & Michigan 582,000Kentucky Power 174,000Ohio & Wheeling 1,497,000PSO (Oklahoma) 532,000SWEPCO (AR, LA, TX) 520,000Texas 961,000
ColumbusSouthern
Power17%
AppalachianPower16%
Indiana &Michigan
10%
All Others5%
PublicService of Oklahoma
6%Southwestern
ElectricPower11%
Texas8%
KentuckyPower
3%
Ohio Power 24%
9
Earnings and DividendsDividend History Since 2004
$/share
$1.71
$1.40 $1.42
$1.50$1.58
$1.64
$1.84
$1.64
1.00
1.20
1.40
1.60
1.80
2.00
2004
2005
2006
2007
2008
2009
2010
2011
E
CAGR = 4.0%
= subject to Board of Directors approval
Dividend increased 12% in 2010 403rd consecutive quarterly dividend
declared in January 2011 50-60% payout ratio target Current yield over 5%
$3.03
$2.33
$2.73$2.77
$3.00 $2.97
$3.10
$3.24
2.00
2.20
2.40
2.60
2.80
3.00
3.20
3.40
3.6020
04
2005
2006
2007
2008
2009
2010
2011
E
On-Going EPS History Since 2004$/share
CAGR = 4.1%
Earnings growth largely attributed to capital investment program
Pre-recession earnings supported by robust wholesale market activity and high power prices
Equity offering in 2009 stabilized credit and strengthened balance sheet
2011 guidance range of $3.00 to $3.20 per share
10
Long-term EPS Growth Rate
4-6% EPS growth 2012-14– Average annual capital spend
between $2.9-3.4B – Utility platform replacement capital
of about $1.4B (annual depreciation)
– Growth in rate base of $1.5-2.0B per year, allocated between utility platform and transmission projects
– Blended ROE of 10.5 - 11%– Slow, steady recovery in economy
5-7% EPS growth post 2014– Base utility platform capital including
generation transformation– Higher allocation of discretionary
capital going to opportunities in the transmission development pipeline
– Higher overall blended ROE opportunity
– Robust economic growth
Average Annual EPS Growth defined over two periods
3.03 3.103.25
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
Period of 5-7% average annual growth
Period of 4-6% average annual growth
11
Summary Rate Case InformationSummary Rate Case InformationAPCo West Virginia General Rate Case – Docket #10-0699-E-42T
On May 14, 2010, APCo filed a base rate case with the West Virginia Public Service Commission requesting a net increase of $155.5 million, comprised of a $223.8 million base rate increase and a $68.3 million decrease in the construction surcharge. The filing related to capital investments made and to recover increased costs. In addition, APCo requested to establish a separate transmission tracker related to PJM charges. The requested ROE was 11.75%. A settlement is on file which stipulates a rate increase of $60MM and the ability to defer $18MM of storm damage expenses. An order is expected by the end of March 2011.
Procedural Schedule
% of Capitalization Cost Rate
Weighted Return
Short-Term Debt 3.66% 0.89% 0.03%Long-Term Debt 53.42% 6.04% 3.23%Common Equity 42.64% 11.75% 5.01%Preferred Stock 0.28% 4.35% 0.01%
Total 100.00% 8.28%
Actual Capital Structure – Company Position (@12/31/09) Required Rate Relief – Company Position (12/31/09)
($ in millions)
July 23, 2010 Company testimony due
November 10, 2010 Staff & Intervenor testimony due
November 24, 2010 Rebuttal testimony due
December 13, 2010 Hearing commences
March 31, 2011 Rates effective
Rate Base 2,639.6$ Rate of Return 8.28%Operating Income Requirement 218.6$ Adjusted Operating Income 86.0$ Difference 132.6$ Revenue Conversion Factor 1.6872
Total Revenue Requirement 223.8$
Elimination of Construction Surcharge (68.3)$
155.5$
12
Approved Rate Bases & ROEs
Jurisdiction Rate Base Approved ROE Approved Debt/Equity Effective Date
APCo-Virginia $2,060MM* 10.53% 58/42 8/1/2010APCo-West Virginia $1,656MM 10.50% 57/43 7/28/2006
KPCo-Kentucky $995MM 10.50% 57/43*** 6/30/2010
I&M-Indiana $2,000MM 10.50% 44/56 3/4/2009I&M-Michigan $595MM 10.35% 50/50 10/14/2010
PSO-Oklahoma $1,706MM 10.15% 54/46 1/5/2011
SWEPCo-Louisiana $649MM 10.57%** 50/50 8/1/2010SWEPCo-Arkansas $612MM 10.25% 54/46 11/25/2009SWEPCo-Texas $665MM 10.33% 49/51 4/15/2010
TCC-Texas $1,566MM 9.96% 60/40 10/17/2007
TNC-Texas $530MM 9.96% 60/40 6/1/2007
* represents Generation and Distribution rate base only.
** represents the midpoint of the ROE range approved in the formula rate case settled in April 2008.
***represents a negotiated settlement
13
$450
$352
$527
$659
$329$45
$162
$28
$0
$100
$200
$300
$400
$500
$600
$700
2006A 2007A 2008A 2009A 2010E 2011E
$ in
mill
ions
Pending/Future
Settlement on filepending approvalSecured
Rate Changes
Note: Rate changes in this chart exclude revenues with offsetting costs
Active or pending rate cases include West Virginia and others yet to be filed
$235
14
Capital Expenditures
$377$266 $361
$331
$272
$434
$729
$808
$776
$130$108
$133
$93
$62$256
$319
$457
$303
$223
$2,270
$47$113 $280
$50
$160
$350
$82$263
$77$34
$24 $56
$1
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
2009A 2010A 2011E 2012E
$ in
mill
ions
AEP Transco
JV EquityContributions, net
AEP River Ops &Other Non-Utility
Environmental
New Generation
Corporate/Other
NuclearGeneration
Distribution
Transmission
Fossil & HydroGeneration
$2,487
$2,243
$2,615$2,900
Investment levels greater than depreciation of $1.4B per year cause rate base growth in 2011 and 2012
15
Cash Flow Guidance
2010A 2011ECash From Operations Income from Continuing Operations 1,218$ 1,499$ Depreciation & Amortization 1,641 1,611 Pension Funding (500) (150) Other Cash Flow Items 659 834 Ligigation Resolution 1 - (449)
Working Capital 2 279 7 Cash From Operations 3,297$ 3,352$
Investing Activities Construction Expenditures (2,318) (2,644) Other Investing Activity (184) (205) Total Investing Activities (2,502)$ (2,849)$
Financing Activities Dividends (824) (892)
Net Debt Issued/(Retired)1 (160) 234 Common Equity 93 150 Other Financing Activities (100) (72) Total from Financing Activities (991)$ (580)$
Beginning Cash Balance 490$ 294$ Ending Cash Balance 294$ 217$
1 Refer to September 30, 2010 10Q Enron Bankruptcy pages 56-57 for futher discussion2 Pro forma to exclude effects of consolidation of AEP Credit ($656M) in 2010
$ in millions
16
Capitalization & Liquidity
57.2%
59.1%60.7%
62.5%
57.2% 57.0%
59.1%
40%
45%
50%
55%
60%
65%
70%
2004
A
2005
A
2006
A
2007
A
2008
A
2009
A
2010
A
Total Debt/Capitalization
Note: Total Debt is calculated according to GAAP and includes securitized debt
1: Effective January 1, 2010 in accordance with Transfers and Servicing accounting guidance (formerly SFAS 166), factored receivables of AEP Credit of $750 million are classified as short-term debt; The 4Q2010 debt/capitalization ratio would be 56.1%, excluding AEP Credit.
Current Liquidity Summary
1
Liquidity Summary Actual(unadited) 12/31/10($ in millions) Amount Maturity
Revolving Credit Facility $1,500 Jun-13Revolving Credit Facility 1,454 Apr-12Revolving Credit Facility 478 Apr-11
Total Credit Facilities 3,432
PlusCash & Cash Equivalents 294
LessCommercial Paper Outstanding (650) Letters of Credit Issued (124) Letters of Credit Issued for VRDNs (477)
Net Available Liquidity $2,475
17
Detailed Ongoing Earnings Guidance
2010A: $3.03 2011E: $3.00 - $3.20
2011 Guidance
Performance Driver ($ millions) Performance Driver ($ millions)UTILITY OPERATIONS:
Gross Margin:1 East Regulated Integrated Utilities 68,761 GWh @ 41.9$ /MWhr = 2,882 67,739 GWh @ 43.4$ /MWhr = 2,940 2 Ohio Companies 49,465 GWh @ 56.6$ /MWhr = 2,800 49,747 GWh @ 56.1$ /MWhr = 2,793 3 West Regulated Integrated Utilities 42,131 GWh @ 31.4$ /MWhr = 1,322 41,536 GWh @ 32.8$ /MWhr = 1,361 4 Texas Wires 27,348 GWh @ 22.3$ /MWhr = 611 27,870 GWh @ 22.0$ /MWhr = 614 5 Off-System Sales 19,172 GWh @ 15.6$ /MWhr = 299 21,786 GWh @ 12.0$ /MWhr = 262 6 Transmission Revenue - 3rd Party 369 429 7 Other Operating Revenue 511 481
8 Utility Gross Margin 8,794 8,880
9 Operations & Maintenance (3,427) (3,529) 10 Depreciation & Amortization (1,598) (1,553) 11 Taxes Other than Income Taxes (801) (818) 12 Interest Exp & Preferred Dividend (945) (921) 13 Other Income & Deductions 154 211 14 Income Taxes (758) (787) 15 Utility Operations On-Going Earnings 1,419 1,483
16 Transmission Operations On-Going Earnings 10 17
NON-UTILITY OPERATIONS:17 AEP River Operations 40 51 18 Generation & Marketing 25 6
19 Parent & Other On-Going Earnings (43) (61)
20 ON-GOING EARNINGS 1,451 1,496
2010 Actual
American Electric PowerFinancial Results for 2011 Guidance vs 2010 Actual
18
2011 Earnings Drivers
$235M in rate changes (69% secured) Weather normalized load growth of 1.7%
Continued discipline in O&M Ohio switching assumptions ($53M – 14% of
CSP total load)
2011 Guidance Range: $3.00 - $3.20/share
0.32
(0.05)
$3.03 $3.10
(0.22) (0.08) (0.07) (0.05) 0.01 0.05 0.06 0.10
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
Weather Other UtilityCosts, net
OhioSwitching
OSS, net ofsharing
Non-Utility/ Parent
TransOperations
O&M, net ofoffsets
SEET Load Recovery
RateChanges,
net ofoffsets
2011E 2010A
19
Normalized Load Trends
2.1% 1.3%
-1.2%
0.6%-0.3% 1.9%
-5%
0%
5%
10%
15%
1Q10 2Q10 3Q10 4Q10 YTD 10 2011E
-1.6%
2.0%
-1.6%-0.4%
0.7%
-0.3%-5%
0%
5%
10%
15%
1Q10 2Q10 3Q10 4Q10 YTD 10 2011E
-1.0%
9.4%
6.0%7.0%
5.3%
1.9%
-5%
0%
5%
10%
15%
1Q10 2Q10 3Q10 4Q10 YTD 10 2011E
-1.6%
2.5%0.8%
1.9% 1.1%1.7%
-5%
0%
5%
10%
15%
1Q10 2Q10 3Q10 4Q10 YTD 10 2011E
AEP Residential Normalized GWh Sales%Change vs. Prior Year
AEP Commercial Normalized GWh Sales%Change vs. Prior Year
AEP Industrial Normalized GWh Sales%Change vs. Prior Year
AEP Total Normalized GWh Sales*%Change vs. Prior Year
*includes firm wholesale load
Note: Chart represents connected load
20
AEP Generation Capacity
20
East Capacity – 27,253 MWAEP Ohio, APCo, I&M, AEG, KPCo, Wind, Solar, Hydro
West Capacity – 11,677 MWPSO, SWEPCO, TNC, Wind
NAPP 46%CAPP 30%PRB 22%Others 2%
Coal76%
NG11%
Nuclear8%
Renewables5%
Coal SourceCoal38%
NG53%
Wind9%
PRB 75%Lignite 25%
Coal Source
Avg. Delivered Cost2009A - $56/ton2010A - $52/ton2011E - $51/ton
Avg. Delivered Cost2009A - $29/ton2010A - $29/ton2011E - $29/ton
0
500
1,000
1,500
2,000
2,500
20-2
4
25-2
9
30-3
4
35-3
9
40-4
4
45-4
9
50+
Non-Controlled - PRB
FGD Only
Coal Unit Age & Installed Controls Coal Unit Age & Installed Controls
0
2,000
4,000
6,000
8,000
10,000
20-2
4
25-2
9
30-3
4
35-3
9
40-4
4
45-4
9
50+
Non-Contro lled -B ituminous
Non-Contro lled -P RB
SNCR Only
SCR Only
FGD Only
FGD & SCR
MW
MW
Age of Unit Age of Unit
21
Continual Evaluation is Required
US Coal
64,000 MW
170,000 MW86,000 MW
Smaller, older, less-efficient coal units that will not be economic if retrofitted
Newer and larger coal units that do not have SCR’s and/or FGD’s will be evaluated due to emerging environmental rulemaking and NSR requirements
AEP Coal
5,000 MW
9,000 MW 10,000 MW
“Fully-Exposed” “Partially-Exposed” “Least-Exposed”Probable Retirement Evaluating potential retirement Not likely to be retired
CCS Candidates
20%
27%53%
20%
36% 44%
“Partially-Exposed”
Evaluating potential retirement
21Nearly 50% of U.S. coal plants are exposed
22
Nuclear6%
Natural Gas 22%
Hydro/Renewables 6%
Coal 66%
Capacity - 2009
Nuclear7%
Natural Gas27%
Hydro/Renewables 8%
Coal 58%
Projected Capacity - 2017
22
Plan for old, small coal units– Initially operate seasonally– Transition towards retirement– Regulatory plan for recovery
Continue evaluation of “partially exposed” units for additional controls
Add non-coal capacity when needed– Dresden NGCC (partially complete)– New NGCC at existing site– Cook plant uprate (under study)– Renewables
Deploy technology as appropriate– Continue pursuit of CCS technology– Energy storage technologies– gridSMART®
Continued Investment in Utility Platform
23
AEP Ohio ESP Filing – Core Policy Issues
Investment in Ohio
Supports economic development and essential tax base
Fundamental barriers must be addressed to attract
investment for Environmental Compliance and New
Generation
Jobs in Ohio
Jobs are a key component of growth
potential in Ohio
Without regulatory assurances over time we could see loss of direct & indirect jobs related to
power generation, and business relocations to
surrounding states
Energy Security
Secure, reliable and predictable electricity
supply is basis for sustained investment and
employment in Ohio
Volatility in power prices can lead to major loss of
economic activity over time
Merged
AEP OhioRate Redesign
Distribution Components
Included
Single merged AEP Ohio company
presumed with supporting
information on an individual OP/CSP
basis
Generation rates redesigned to
resemble market pricing structures
Inclusion of certain distribution
components while pursuing a parallel distribution base
rate case
29-Month ESP Period
ESP period Jan 1, 2012 through May 31,2014 (May 31 date aligns with
PJM annual planning cycle)
Alternative Long Term Option
Alternative longer-term price certainty option offered for
qualifying commercial &
industrial customers
Ohio Growth Fund
Creation of significant private sector economic development to
attract investment and job growth in AEP Ohio service
territory
Primary objective of ESP: Stabilize rates and support economic development in the state of Ohio
24
Summary of ESP Filing - Continued
Pre-tax earnings impact from proposed ESP (excluding potential earnings impact from trackers)
Net base $54MM or 1.4% in year 1 (2012)
Net base $106MM or 2.7% in year 2 (2013)
While the ESP includes a small base generation increase, the move to a market-based rate design, consistent with state policy, will result in varying impacts for different customer groups.
Revenue $/MWh % Revenue $/MWh % Revenue $/MWh %
Proposed ESP Changes
Base Generation $65MM $1.50 1.7% $106MM $2.43 2.7% N/C* N/C* N/C*
POLR ($11MM) ($0.23) (0.3%) N/C* N/C* N/C* N/C* N/C* N/C*
FAC Actual Recovery 2012-2014
Actual Actual Actual
N/C* = No change from prior year
2012 2013 2014
25
Price to CompareProposed SSO Rates Redesigned To Resemble Market Pricing Structures
The realignment of rates with market should provide all customers with equivalent opportunities to shop. Additionally, since the proposed design eliminates explicit demand charges, customers should be more easily able to evaluate
competitive offers. To ease the rate impact that customers will experience from the realignment, we have proposed a Market Transition Rider.
Rates do not reflect mitigation impact of market transition rider2012 Rates before ESP reflect current 2011 rates for generation & transmission service, adjusted to reflect full cost 2011 fuel and environmental costs.
40
50
60
70
80
90
100
CSP RS OP RS CSP GS1 OP GS1 CSP GS2 OP GS2 CSP GS3 OP GS3 CSP GS4 OP GS4
Tariff Class
$/M
Wh
2012 Rates before ESP 2012 ESP Rates 2013 ESP Rates
26
Market Transition Rider – Mitigates the Initial Impact of Rate Realignment
Illustration of Market Transition Rider on ESP Generation Rate
Increases
The Market Transition Rider is a transition rider designed to facilitate the transition from AEP Ohio’s current rates to market-based SSO Generation Service rates. It is a non-bypassable rider designed to limit the first
and second year changes for any customer classes to uniformly transition any above or below average changes in three steps. Any revenue shortfall that is produced by limiting the increases for certain customer
classes is collected from those classes whose decreases are limited.
Three‐Year Market Transition Plan Summary of AEP Ohio ESP Generation Rate Changes
CSP Current Customer Class
CSP New Customer Class
2012 Increase
2013 Increase
2014 Increase
Total Increase
Residential Residential 5.0% 3.9% 1.0% 10.2% GS1 GS Non‐Demand (6.4%) (5.2%) (7.8%) (18.1%) GS2 (5.3%) (5.5%) (8.2%) (17.8%) GS3 (0.3%) 1.0% (1.8%) (1.2%) GS4/IRP
GS Demand 2.3% 7.7% 4.7% 15.3%
Total CSP 2.2% 2.7% 0.0% 5.0% OPCo Current Customer Class
OPCo New Customer Class
2012 Increase
2013 Increase
2014 Increase
Total Increase
Residential Residential 6.0% 3.1% 0.3% 9.7% GS1 GS Non‐Demand 1.5% (3.3%) (6.1%) (7.8%) GS2 0.1% (0.7%) (3.5%) (4.1%) GS3 (0.7%) 2.8% (0.0%) 2.0% GS4/IRP
GS Demand (6.6%) 5.8% 3.0% 1.7%
Total OPCo 0.4% 2.7% 0.0% 3.1% AEP Ohio 1.4% 2.7% 0.0% 4.2%
27
List of ESP Riders – Existing and Proposed
Line Rate Mechanism Abbreviation Bypassable Distribution Notes
1 Current Riders2 Universal Service Fund Rider USF -- Yes3 Advanced Energy Fund Rider AEF -- Yes Expired 12/31/20104 kWh Tax Rider kWh Tax -- May be self-assessed under specific terms5 Provider of Last Resort Charge POLR No Option to avoid under specific terms6 Monongahela Power Litigation Termination Rider Mon Power -- Yes Expires once amount collected7 Transmission Cost Recovery Rider TCRR Yes8 Fuel Adjustment Clause Rider FAC Yes
9 Energy Efficiency and Peak Demand Reduction Cost Recovery Rider EE/PDR -- Yes
10 Economic Development Cost Recovery Rider EDR -- Yes11 Enhanced Service Reliability Rider ESRR -- Yes12 gridSMART® Rider gridSMART® -- Yes13 Environmental Investment Carrying Cost Rider EICCR No1415 Proposed Riders16 Standard Offer Generation Service Rider GSR Yes Relocation of base generation rates17 Generation Resource Rider GRR No Capital/solar investment18 Alternative Energy Rider AER Yes Relocation of RECs from FAC19 Phase-In Recovery Rider PIRR -- Yes Previous ESP deferrals, possibility of securitization20 Distribution Investment Rider DIR -- Yes21 Market Transition Rider MTR -- Yes22 Generation NERC Compliance Cost Recovery Rider NERCR No23 Facility Closure Cost Recovery Rider FCCR No24 Carbon Capture and Sequestration Rider CCSR No2526 Other Provisions27 Green Power Portfolio Rider GPPR -- Voluntary28 Rate Security Rider RSR -- Voluntary29 Plug-In Electric Vehicle Tariff / Costs PEV -- Yes Voluntary, Deferral of Costs30 Emergency Curtailable Service Rider ECS -- Voluntary, pending31 Storm Damage Recovery Mechanism -- Yes Reconciliation of storm experience to funding level32 Pool Termination or Modification Provision Yes33 PIPP Uncollectibles PIPP -- Yes
the current bypassable rider is proposed to be nonbypassable in the new ESP
28
Ohio Timeline
AEP Ohio’s long-term strategy is designed to produce rate relief for items currently known as well as anticipated future items. The filings and riders we seek today are designed to be broad and flexible enough to accommodate a variety of
circumstances, because it is impossible to know all variables and specific items for which we will desire to seek rate relief or what regulatory circumstances will prevail at the time.
Distribution CaseFACESP Recovery &
Risk Mitigation
Regulatory ActivityJan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Merger of CSP & OP
Proposed ESP
Distribution Case
Capacity Charge (FRR) Filing
Trans. Cost Recovery Rider
Environmental Rider
FAC Filings
Sporn 5 Cost Recovery Request
Annual SEET Filing Dates
1Q12 2Q12 3Q12 4Q121Q11 2Q11 3Q11 4Q111Q10 2Q10 3Q10 4Q10
PUCO Application
FERC Application
Expected Closure
ESP Application Filed Proposed ESP Rates & Mechanisms in Place
Distribution Base Case Notification Filed
Sporn 5 Closure Cost Recovery Application Filed
1st SEET Annual Filing (FY2009)
SEET Order Received
2nd SEET Annual Filing (FY2010)
3rd SEET Annual Filing (FY2011)
Annual Filing Annual Filing Annual Filing
Rates May Be Implemented Subject to Refund
Annual Filing Annual Filing Annual Filing
Annual Audit Annual Audit Annual Audit
FERC Filing FERC Ordered adherence to PUCO mechanism
PUCO Opens InvestigationFiling for FERC Rehearing due by 2/2/11
AEP files motion & memorandum to stay the reply comment period & establish procedural schedule; PUCO grants motion for extension
(Qtrly)
(2012-2014)
Notification of $93.2MM base case filed Jan 27, 2011
Recommended